Apparatuses and methods for fluid catalytic cracking with limited particulate emissions

ABSTRACT

Methods and apparatuses are provided for cracking a hydrocarbon. The method includes contacting a first hydrocarbon stream with a cracking catalyst in a riser. The cracking catalyst is regenerated in a regenerator to produce a flue gas stream having a particulate concentration, where the flue gas stream is vented. A second stream is contacted with the cracking catalyst in the riser while the first hydrocarbon stream is contacted with the catalyst, where the second stream includes a natural oil. The particulate concentration is a second particulate concentration while the second stream contacts the cracking catalyst, and a first particulate concentration prior to the second stream contacting the cracking catalyst. The first particulate concentration is greater than the second particulate concentration.

TECHNICAL FIELD

The present disclosure generally relates to apparatuses and methods usedin fluid catalytic cracking, and more particularly relates toapparatuses and methods for limiting particulate emissions when crackinghydrocarbons in a fluid catalyst cracking unit.

BACKGROUND

Fluid catalytic cracking (FCC) is primarily used to convert highboiling, high molecular weight hydrocarbons from petroleum into lowerboiling, lower molecular weight compounds. The lower molecular weightcompounds include gasoline, olefinic compounds, liquid petroleum gas(LPG), diesel fuel, kerosene, etc., where the feedstock and theoperating conditions can be adjusted to shift yields to a desiredproduct. During FCC, hydrocarbons are cracked with a catalyst in a riserin an FCC unit, coke deposits on the catalyst in the riser, and the cokeis burned off in a regenerator to regenerate the catalyst. The catalystis repeatedly cycled through the riser and regenerator while crackinghydrocarbons.

A regenerator flue gas steam includes solid particulates that aredischarged from the FCC unit. The particulates are primarily catalystfines that escape a catalyst separator and exit the regenerator with theflue gas. Particulate emissions are limited by air permits, and avariety of pollution control devices are used to minimize theparticulate emissions including flue gas scrubbers, third and fourthstage separators, dust collectors, and electrostatic precipitators. Thepollution control devices require capital expenditure for installation,as well as ongoing operating costs. However, often low levels ofparticulates still escape the pollution control devices and aredischarged into the atmosphere.

Accordingly, it is desirable to develop methods and apparatuses forreducing particulate emissions from FCC units. In addition, it isdesirable to develop methods and apparatuses for reducing particulateemissions from FCC units without the installation of additionalpollution control devices. Furthermore, other desirable features andcharacteristics of the present embodiment will become apparent from thesubsequent detailed description and the appended claims, taken inconjunction with the accompanying drawing and this background.

BRIEF SUMMARY

Apparatuses and methods are provided for fluid catalytic cracking. In anexemplary embodiment, a method includes contacting a first hydrocarbonstream with a cracking catalyst in a riser. The cracking catalyst isregenerated in a regenerator to produce a flue gas stream having aparticulate concentration, where the flue gas stream is vented. A secondstream is contacted with the cracking catalyst in the riser while thefirst hydrocarbon stream is contacted with the catalyst, where thesecond stream includes a natural oil. The particulate concentration is asecond particulate concentration while the second stream contacts thecracking catalyst, and a first particulate concentration prior to thesecond stream contacting the cracking catalyst. The first particulateconcentration is greater than the second particulate concentration.

In another embodiment of fluid catalytic cracking, a feedstock iscontacted with a cracking catalyst in a riser to produce a risereffluent in a gaseous state. The cracking catalyst includes crackingcatalyst fines having a diameter of about 0.04 millimeters or less. Theriser effluent is separated from the cracking catalyst in a risercatalyst separator, and about 25 weight percent or more of the crackingcatalyst fines exit the riser catalyst separator with the risereffluent.

A fluid catalytic cracking unit is provided in yet another embodiment.The fluid catalytic cracking unit includes a riser and a regeneratorcoupled to the riser. A first inlet is coupled to the riser, and asecond inlet is coupled to the riser about 0.5 to about 12 meters abovethe first inlet. The first and second inlets are configured to introducea first hydrocarbon stream and a second stream to the riser, where thesecond stream includes a natural oil.

BRIEF DESCRIPTION OF THE DRAWINGS

Various embodiments will hereinafter be described in conjunction withthe FIGURE, which is a cross sectional view of an exemplary embodimentof an apparatus and method for cracking hydrocarbons, wherein likenumerals denote like elements.

DETAILED DESCRIPTION

The following detailed description is merely exemplary in nature and isnot intended to limit the application or uses of the embodimentdescribed. Furthermore, there is no intention to be bound by any theorypresented in the preceding technical field, background, brief summary,or the following detailed description.

Apparatuses and methods for cracking hydrocarbons with reducedparticulate emissions are provided. In accordance with variousembodiments, a feedstock is introduced into a riser of a fluid catalystcracker (FCC) unit, and contacted with a cracking catalyst at crackingconditions. A natural oil is added to the riser as a co-feed or as thefeedstock, where the natural oil is introduced to the riser prior tobeing hydrotreated. The natural oil includes some char or ash in variousembodiments. During commercial scale testing it was discovered that theaddition of pyrolysis oil at an introduction point above a vacuum gasoil introduction point reduced particulate emissions in the regeneratorflue gas. The pyrolysis oil was introduced prior to any hydrotreating.The reason for the reduction in particulate emissions is not known withcertainty, but, without wishing to be bound by theory, it is believedthat the catalyst fines in the riser are bound to components within thenatural oil. The catalyst fines and the natural oil components havecombined density and aerodynamic characteristics such that the catalystfines and natural oil components pass through a riser catalyst separatorand flow to an FCC fractionation unit, where the catalyst fines collectin a slurry oil. Because the catalyst fines are not transferred to theregenerator, they are not discharged with the flue gas from theregenerator and, accordingly, the FCC unit particulate emissions arereduced.

In accordance with an exemplary embodiment and referring to the FIGURE,an FCC unit 10 includes a riser 12 and a regenerator 40. A firsthydrocarbon stream 14 is introduced to the riser 12 for cracking at afirst inlet 16, where the first hydrocarbon stream 14 is a feedstock forthe riser 12. The first hydrocarbon stream 14 is a petroleum oil in anexemplary embodiment, but the first hydrocarbon stream 14 mayalternatively be a natural oil, a chemical by-product, other materials,or a combination of materials in alternate embodiments. Suitablehydrocarbon feedstocks for the first hydrocarbon stream 14 include, butare not limited to, petroleum oils such as vacuum gas oil (VGO),hydrotreated VGO, atmospheric distillation column bottoms, demetallizedoil, deasphalted oil, hydrocracker main column bottoms, combinations ofthe above, or other petroleum oils. Other suitable components for thefirst hydrocarbon stream 14 include Fischer-Tropsch liquids derived fromrenewable or non-renewable feedstocks, triglycerides of vegetable oranimal origin, natural oils, and the like. In some embodiments, thefirst hydrocarbon stream 14 has an initial boiling point of about 300degrees centigrade (° C.) or higher (at atmospheric pressure), and is amaterial that can vaporize and flow. In many embodiments, the firsthydrocarbon stream 14 will be a mixture of different compounds, so itwill have a boiling range instead of a single boiling point, where theboiling range begins at the initial boiling point described above. Insome embodiments, the hydrocarbons have an average molecular weight ofabout 200 to about 600 Daltons or higher.

The first hydrocarbon stream 14 is contacted with a cracking catalyst 18in the riser 12. The cracking catalyst 18 can be a wide variety ofcracking catalysts 18 as is known in the art. Suitable crackingcatalysts 18 for use herein include high activity crystalline aluminasilicate and/or zeolite, which may be dispersed in a porous inorganiccarrier material such as silica, alumina, zirconia, or clay. Anexemplary embodiment of a cracking catalyst 18 includes crystallinezeolite as the primary active component, a matrix, a binder, and afiller. The zeolite ranges from about 10 to about 50 mass percent of thecatalyst, and is a silica and alumina tetrahedral with a latticestructure that limits the size range of hydrocarbon molecules that canenter the lattice. In an embodiment, the matrix component includesamorphous alumina, and the binder and filler provide physical strengthand integrity. For example, silica sol or alumina sol are used as thebinder and kaolin clay is used as the filler. Different crackingcatalysts 18 may be used in alternate embodiments. The cracking catalyst18 may include cracking catalyst fines, where the fines are particles ofthe cracking catalyst 18 with a diameter of about 0.04 millimeter(mm)(40 microns) or less, such as about 0.04 mm to about 0.000001 mm.The “diameter” of the fines is defined herein as the largest dimensionof the particle.

The first inlet 16 is positioned at a low portion of the riser 12, sothe first hydrocarbon stream 14 travels upward through most of thelength of the riser 12. For example, the first inlet 16 may be fromabout 0.1 meters to about 3 meters from the bottom of the riser 12,where the riser 12 may be about 5 to about 20 meters tall, but otherdimensions are also possible. The hydrocarbons in the first hydrocarbonstream 14 are vaporized, carried up through the riser 12 with thecracking catalyst 18, and react (crack) primarily within the riser 12.The cracking catalyst 18 is fluidized in the riser 12 by a riser gasdistributor 20, where the riser gas distributor 20 may include one ormore of steam, light hydrocarbons, nitrogen, or other gases. The firsthydrocarbon stream 14 is typically introduced into the riser 12 as aliquid, and the hydrocarbons in the first hydrocarbon stream 14 arevaporized by heat from the hot cracking catalyst 18. As the vaporizedhydrocarbons and cracking catalyst 18 rise up through the riser 12, thehydrocarbons are contacted with the cracking catalyst 18 and crackedinto smaller hydrocarbons.

In an exemplary embodiment, the riser 12 operates at crackingtemperature of from about 450° C. to about 600° C. (about 840 degreesFahrenheit (° F.) to about 1,100° F.). The cracking temperature ismeasured in the vaporous stream at or near an outlet 28 of the riser 12,where “near the outlet” is defined to mean within about 1 meter of theoutlet 28. Operating pressures in the riser 12 may be from about 100kilo Pascals gauge (kPa) to about 250 kPa (about 15 pounds per squareinch gauge (PSIG) to about 35 PSIG). The operating conditions may varydepending on several factors, including but not limited to, thefeedstock in the first hydrocarbon stream 14, the cracking catalyst 18,residence time in the riser 12, catalyst loading in the riser 12, thedesired product, etc. The riser 12 is generally designed for a givenfeedstock and production rate, so the size, flow rate, and proportionscan vary widely. In an exemplary embodiment, the riser 12 is designedfor a first hydrocarbon stream 14 residence time of from about 0.5 toabout 10 seconds, but other residence times are also possible. The firsthydrocarbon stream 14 may be heated to a temperature of from about 150°C. to about 450° C. (300° F. to 850° F.) before entry into the riser 12.

In an exemplary embodiment, the first hydrocarbon stream 14 and crackingcatalyst 18 travel up the riser 12 to a riser catalyst separator 22fluidly coupled to the riser 12. The vaporous hydrocarbons exit theriser catalyst separator 22 in a riser effluent 24 and the crackingcatalyst 18 exits the riser catalyst separator 22 and collects in ariser catalyst collector 26. Coke is deposited on the cracking catalyst18 in the riser 12 such that the cracking catalyst 18 is at leastpartially coated with coke when falling into the riser catalystcollector 26. The riser catalyst separator 22 may be one or morecyclones, impingement separators, other gas/solid separators, orcombinations thereof. The cracking catalyst 18 is transferred to aregenerator 40 fluidly coupled to the riser catalyst collector 26, andthe riser effluent 24 flows to a fractionation zone 60, as discussedbelow.

In an exemplary embodiment, a second stream 30 is introduced to theriser 12 at a second inlet 32, where the second stream 30 is anotherfeedstock for the riser 12. The second inlet 32 is above the first inlet16, and may be about 0.5 to about 12 meters above the first inlet 16 onthe riser 12. In alternate embodiments, the second inlet 32 is about 1to about 8 meters above the first inlet 16, or about 4 to about 6 metersabove the first inlet 16. The second stream 30 is largely vaporized whenit contacts the hot cracking catalyst 18 in the riser 12, and it iscarried up the riser 12 with the vaporous first hydrocarbon stream 14.The second stream 30 may be atomized with an atomizing gas (notillustrated) when introduced to the riser 12. However, in thisdescription, the composition of the second stream 30 as described belowrefers to the composition of the second stream 30 prior to beingatomized, so the atomizing gas is not included in the composition of thesecond stream 30. Oxygenated hydrocarbons present in the second stream30 may be cracked and deoxygenated to produce hydrocarbons. In anexemplary embodiment, the second stream 30 is about 0.1 weight percentto about 100 weight percent of the total feedstock introduced to theriser 12. In other embodiments, the second stream 30 is about 0.1 weightpercent to about 10 weight percent, or about 0.5 weight percent to about10 weight percent, or about 1 weight percent to about 10 weight percentof the total feedstock introduced to the riser 12. The remainingfeedstock is introduced by the first hydrocarbon stream 14 and possiblyby optional additional hydrocarbon streams (not illustrated) introducedto the riser 12 in alternate embodiments.

In an exemplary embodiment, the second stream 30 includes a natural oil,such as pyrolysis oil, vegetable oil, or other oils. One particularexample of a natural oil in the second stream 30 is pyrolysis oil. Thesecond stream 30 may include about 20 weight percent to about 100 weightpercent natural oil in an exemplary embodiment, or about 50 to about 100weight percent natural oil, or about 80 to about 100 weight percentnatural oil in alternate embodiments. The natural oil in the secondstream 30 may be about 90 to about 100 weight percent pyrolysis oil inan exemplary embodiment, but other types of natural oil may be used inalternate embodiments. Pyrolysis oil is produced by thermallydecomposing organic matter in the absence of oxygen. In someembodiments, the pyrolysis oil is produced by rapid thermal pyrolysis,where the organic matter is rapidly heated to a reaction temperature ofabout 400° C. to about 900° C., maintained at the reaction temperaturefor about 0.5 to 2 seconds, and the vapors formed are then rapidlycooled to quench the pyrolysis reaction. In an exemplary embodiment, thepyrolysis oil in the second stream 30 may include about 0.1 to about 10weight percent char, based on the total weight of the second stream 30,or about 0.1 weight percent or greater, but other concentrations arealso possible. The char may not vaporize in the riser 12, so the charmay remain in the solid state and pass through the riser 12 as a solidwithout significant cracking.

The second stream 30 may be introduced to the riser 12 at a temperatureof about 90 degrees centigrade (° C.) or less, such as about 90° C. toabout 0° C., in some embodiments. A second inlet heat exchanger 34 maybe used to control the temperature of the second stream 30. In anexemplary embodiment, the pyrolysis oil may include large organicmolecules, including heavy rosins and heavy oxygenated hydrocarbons thatmay remain as a solid or liquid in the riser 12, and these large organicmolecules may “stick” to the cracking catalyst fines. Organic moleculesare generally less dense and have higher length to diameter ratios thanthe cracking catalyst 18, so the bound organic molecules and crackingcatalyst fines are more prone to not being collected in cycloneseparators than the cracking catalyst fines without the organicmolecules. This may allow the cracking catalyst fines to escape theriser catalyst separator 22 in the riser effluent 24. There may be otherreasons why the pyrolysis oil reduces the particulate emissions inaddition to, or in place of, the theories discussed herein.

In any event, the cracking catalyst fines are entrained in the risereffluent 24 and exit the riser catalyst separator 22 with the risereffluent 24. In an exemplary embodiment, about 25 weight percent of thecatalyst fines exit the riser catalyst separator 22 with the risereffluent 24, and about 50 weight percent of the catalyst fines exit theriser catalyst separator 22 with the riser effluent 24 in anotherembodiment. The riser effluent 24 and the cracking catalyst fines areintroduced to the fractionation zone 60. The fractionation zone 60includes one or more distillation columns that separate the risereffluent 24 into various fractions, such as a fractionation zone lightsstream 62, a fractionation zone first stream 64, a fractionation zonesecond stream 66, a heavy cycle oil 68, and a slurry oil 70. A widevariety of operating conditions can be used in the fractionation zone 60in different embodiments, such as a pressure from about 100 kPa to about200 kPa (14 PSIG to 30 PSIG) and a temperature of about 80° C. to about140° C. (180° F. to 280° F.) at the overhead. The lightest compoundswith the highest vapor pressures and lowest boiling points aredischarged in the fractionation zone lights stream 62. The heavy cycleoil 68 is discharged from near the bottom of a distillation column inthe fractionation zone 60, and the slurry oil 70 is discharged from thebottom. The heavy cycle oil 68 may optionally be combined with theslurry oil 70 in an exemplary embodiment, as illustrated. The slurry oil70 includes the cracking catalyst fines that entered the fractionationzone 60 with the riser effluent 24, because the cracking catalyst finesflow downward with high-boiling liquids in the fractionation zone 60.

The heavy cycle oil 68 and the slurry oil 70 include the heaviestcompounds with the highest boiling points. The fractionation zone firstand second streams 64, 66 may have various compositions in differentembodiments, such as a naphtha, a diesel boiling range material, akerosene boiling range material, a gasoline boiling range material, etc.The operating conditions in the riser 12, the feedstock in the firsthydrocarbon stream 14, and the second stream 30, and the operatingconditions within the fractionation zone 60 determine the number ofstreams and the composition of the streams exiting the fractionationzone 60. The slurry oil 70 may have a higher cracking catalyst load inembodiments where the particulates are reduced, but the higher crackingcatalyst loading may not interfere with many uses of the slurry oil 70.For example, the slurry oil 70 may be used for asphalt, marine (bunker)fuel, fuel oil, carbon black, needle coke, or other purposes. Certainuses for the slurry oil 70 may limit the amount of suspended crackingcatalyst 18, such as with an alumina specification, so increasedcracking catalyst 18 concentrations may or may not limit the potentialuses for the slurry oil 70.

In an exemplary embodiment, the cracking catalyst 18 from the risercatalyst collector 26 is transferred to the regenerator 40 to oxidizethe coke deposits formed on the cracking catalyst 18 in the riser 12,which is often referred to as burning off the coke. Coke is burnt offthe mixed spent cracking catalyst 18 in a combustion zone 42 to producea flue gas stream 44 and regenerated cracking catalyst 18. The crackingcatalyst 18 is separated from the flue gas stream 44 in a regeneratorcatalyst separator 46, such as one or more cyclones, impingementseparators, other gas/solid separators, or combinations thereof, and thecracking catalyst 18 is collected in a regenerator catalyst collector48. An oxygen supply gas 50 is coupled to the combustion zone 42 andcarries the fluidized cracking catalyst 18 through the combustion zone42. The coke is burned off the cracking catalyst 18 by contact with theoxygen supply gas 50 at regeneration conditions. In an exemplaryembodiment, air is used as the oxygen supply gas 50, because air isreadily available and provides sufficient O₂ for combustion, but othergases with a sufficient concentration of O₂ could also be used, such aspurified O₂. If air is used as the oxygen supply gas 50, about 10 toabout 15 kilograms (kg) of air is required per kg of coke burned off ofthe cracking catalyst 18. Exemplary regeneration conditions include atemperature from about 500° C. to about 900° C. (900° F. to 1,700° F.)and a pressure of about 150 kPa to about 450 kPa (20 PSIG to 70 PSIG).The superficial velocity of the oxygen supply gas 50 is typically lessthan about 2 meters per second (6 feet per second), and the densitywithin the combustion zone 42 is typically about 80 to about 400kilograms per cubic meter (about 5-25 lbs. per cubic foot). However, theregenerator 40 may be designed and sized based on the expected duty, sothe regenerator 40 may be larger or smaller than as described above.

The hydrocarbon cracking reaction is endothermic, and heat is requiredto vaporize the hydrocarbons from the first hydrocarbon stream 14 andthe second stream 30. In some embodiments, the heat is primarilysupplied by the cracking catalyst 18 transferred from the regenerator 40to the riser 12. As such, the FCC unit 10 may be about energy neutral,in that the energy used to vaporize and crack the hydrocarbons isprimarily provided by the energy released from regenerating the crackingcatalyst 18. In an exemplary embodiment, about 70 percent of the heatused in the riser 12 is used to vaporize the first hydrocarbon stream 14and the second stream 30 with about 30 percent used to drive theendothermic cracking reaction, depending on the operating conditions andthe composition of the first hydrocarbon stream 14 and the second stream30.

The flue gas stream 44 includes combustion gases, such as carbondioxide, carbon monoxide, and water, and may also include nitrogen orother gases. The combustion gases and other excess gases may be ventedfrom the regenerator 40 in the flue gas stream 44, and the flue gasstream 44 may pass through one or more pollution control devices 52before being vented to the atmosphere. The flue gas stream 44 alsoincludes particulates at a particulate concentration. The particulateconcentration in the flue gas stream 44 can be characterized as a firstparticulate concentration when the second stream 30 is not contactingthe cracking catalyst 18, such as either before or after the secondstream 30 contacts the cracking catalyst 18. The particulateconcentration is a second particulate concentration when the secondstream 30 is contacting the cracking catalyst 18, and the secondparticulate concentration is less than the first particulateconcentration. In this description, all particulate concentrations inthe flue gas stream 44 are from before the pollution control device 52.In an exemplary embodiment, the second particulate concentration isabout 90 weight percent or less of the first particulate concentration(a 10 percent or greater reduction), or about 50 weight percent or less(a 50 percent or greater reduction), or about 30 weight percent or less(a 70 percent or greater reduction) in alternate embodiments. In anexemplary embodiment, an opacity of the flue gas stream 44 before thepollution control device 52 decreases by about 50% or more when thesecond stream 30 is contacted with the cracking catalyst 18, or by about80% or more or about 90% or more in alternate embodiments. The decreasein opacity is based on the opacity prior to the second stream 30contacting with the cracking catalyst 18 relative to the opacity whilethe second stream 30 contacts the cracking catalyst 18. Opacityindicates the particulate concentration in the flue gas stream 44, butopacity can be influenced by other factors as well. Higher particulateconcentrations in the flue gas stream 44 before the pollution controldevice 52 generally produce higher particulate concentrations in theflue gas stream 44 after the pollution control device 52, because thepollution control device 52 is not perfectly efficient. The combustionof coke is an exothermic reaction, so the cracking catalyst 18 is heatedas it is regenerated. In an exemplary embodiment, the cracking catalyst18 has a temperature of about 600° C. to about 760° C. (about 1,100° F.to about 1,400° F.) when transferred from the regenerator 40 to theriser 12.

The cracking catalyst fines pass to the fractionation zone 60 with theriser effluent 24, so the cracking catalyst fines do not pass to theregenerator 40. Much of the particulates typically discharged to theatmosphere with the flue gas stream 44 are cracking catalyst fines, sothe removal of the cracking catalyst fines before the cracking catalyst18 is transferred to the regenerator 40 reduces the quantity of crackingcatalyst fines discharged with the flue gas stream 44. Some crackingcatalyst fines may be produced in the regenerator 40, but the totalquantity of cracking catalyst fines in the flue gas stream 44 arereduced by the addition of the second stream 30 to the riser 12.

Example

A commercial scale test was conducted where natural oil was added as aco-feed with vacuum gas oil. The natural oil was a pyrolysis oil withoutfiltration or hydrogenation, where the pyrolysis oil was produced by afast pyrolysis process. The vacuum gas oil was introduced to the riserat a first inlet, and the natural oil was introduced to the riser at asecond inlet that was 5.01 meters (16 feet 0 inches) above the firstinlet. The natural oil was added at a temperature from 46° C. to 74° C.(115 degrees Fahrenheit (° F.) to 165° F.) at flow rates up to 8.5liters per minute (2.25 gallons per minute). The natural oil wasatomized with nitrogen gas supplied at 800 kPa (116 pounds per squareinch gauge). A total of about 6,435 liters (1,700 gallons) of naturaloil was added over a period of 16 hours. The vacuum gas oil feed ratewas 1,240,000 liters per day (7,800 barrels per day) during the test.

The initial natural oil feed rate was about 0.5% of the vacuum gas oilfeed rate, and the opacity of the emissions from the flue gas on theregenerator went from a range of about 1.25 to 1.5 percent to anon-detectable reading within about 1 hour, where the opacity steadilydropped from the time the test began to the point where the opacity wasnon-detectable (less than about 0.1 percent). The opacity is one methodof measuring the particulate levels in the flue gas vented from theregenerator, where opacity is typically measured using a lightscattering or absorption technique. Opacity does not provide an exactquantity of the particulate emissions, but quantification of theparticulate emissions described above is a conservative estimate basedon the opacity readings observed, where opacity dropped to anon-detectable level. The opacity remained at a level of less than 0.1percent for the duration of the test, and the opacity returned to avalue ranging from about 1.25 to about 1.75 percent within 12 hours ofthe termination of the test, with a steady increase in the opacity fromthe time the test was terminated until the opacity was within the rangeof 1.25 to 1.75 percent. The flue gas sulfur oxide emissions (SOx)remained stable and unchanged from before the test, through the periodof the test, and after the test. Analysis of the slurry oil showedincreased levels of solids, aluminum, magnesium, and vanadium after thetest began, indicating a higher catalyst concentration in the slurryoil. The catalyst that was used included aluminum, magnesium, andvanadium, so the increased concentrations in the slurry oil indicate anincreased catalyst concentration in the slurry oil. The slurry oil alsobecame darker as the test proceeded.

While at least one exemplary embodiment has been presented in theforegoing detailed description, it should be appreciated that a vastnumber of variations exist. It should also be appreciated that theexemplary embodiment or exemplary embodiments are only examples, and arenot intended to limit the scope, applicability, or configuration of theapplication in any way. Rather, the foregoing detailed description willprovide those skilled in the art with a convenient road map forimplementing one or more embodiments, it being understood that variouschanges may be made in the function and arrangement of elementsdescribed in an exemplary embodiment without departing from the scope,as set forth in the appended claims.

What is claimed is:
 1. A method of fluid catalytic cracking, the methodcomprising the steps of: contacting a first hydrocarbon stream with acracking catalyst in a riser; regenerating the cracking catalyst in aregenerator to produce a flue gas stream; venting the flue gas stream,wherein the flue gas stream comprises particulates at a particulateconcentration; contacting a second stream with the cracking catalyst inthe riser while contacting the first hydrocarbon stream with thecracking catalyst, wherein the second stream comprises a natural oil,and wherein the particulate concentration is a second particulateconcentration while the second stream contacts the cracking catalyst,the particulate concentration is a first particulate concentration priorto the second stream contacting the cracking catalyst, and the secondparticulate concentration is less than the first particulateconcentration.
 2. The method of claim 1 where contacting the secondstream with the cracking catalyst comprises contacting the second streamwith the cracking catalyst wherein the second stream comprises about 50to about 100 percent natural oil.
 3. The method of claim 1 whereincontacting the second stream with the cracking catalyst comprisescontacting the second stream with the cracking catalyst wherein thesecond stream comprises pyrolysis oil.
 4. The method of claim 3 whereincontacting the second stream with the cracking catalyst comprisescontacting the second stream with the cracking catalyst wherein thesecond stream comprises the pyrolysis oil without hydrotreating.
 5. Themethod of claim 3 wherein contacting the second stream with the crackingcatalyst comprises contacting the second stream with the crackingcatalyst wherein the second stream comprises char.
 6. The method ofclaim 1 wherein contacting the second stream with the cracking catalystcomprises contacting the second stream with the cracking catalystwherein the second particulate concentration is about ninety weightpercent or less of the first particulate concentration.
 7. The method ofclaim 1 further comprising: introducing the first hydrocarbon stream tothe riser in a first inlet; introducing the second stream to the riserin a second inlet, wherein the second inlet is about 0.5 to about 12meters above the first inlet on the riser.
 8. The method of claim 1further comprising: introducing the first hydrocarbon stream to theriser in a first inlet as a feedstock, wherein the first hydrocarbonstream comprises hydrocarbons; introducing the second stream to theriser as the feedstock, wherein the second stream comprises about 0.5 toabout 10 weight percent of the feedstock introduced to the riser.
 9. Themethod of claim 1 further comprising: separating a riser effluent fromthe cracking catalyst in a riser catalyst separator, wherein thecracking catalyst comprises cracking catalyst fines; entraining thecracking catalyst fines in the riser effluent; and introducing the risereffluent to a fractionation zone.
 10. The method of claim 1 furthercomprising: measuring the particulate concentration in the flue gasstream as an opacity; and wherein contacting the second stream with thecracking catalyst comprises contacting the second stream with thecracking catalyst in the riser wherein the opacity of the flue gasdecreases by about 50 percent or more when the second stream iscontacting the cracking catalyst relative to the opacity prior to thesecond stream contacting the cracking catalyst.
 11. A method of fluidcatalytic cracking, the method comprising the steps of: contacting afeedstock with a cracking catalyst in a riser to produce a risereffluent in a gaseous state, wherein the cracking catalyst comprisescracking catalyst fines having a diameter of about 0.04 millimeters orless; and separating the riser effluent from the cracking catalyst in ariser catalyst separator, wherein about 25 weight percent or more of thecracking catalyst fines exit the riser catalyst separator with the risereffluent.
 12. The method of claim 11 wherein contacting the feedstockwith the cracking catalyst comprises contacting the feedstock whereinthe feedstock comprises pyrolysis oil.
 13. The method of claim 11wherein contacting the feedstock with the cracking catalyst comprises:introducing a first hydrocarbon stream to the riser at a first inlet;and introducing a second stream to the riser at a second inlet above thefirst inlet.
 14. The method of claim 13 wherein introducing the firsthydrocarbon stream to the riser comprises introducing the firsthydrocarbon stream to the riser wherein the first hydrocarbon streamcomprises a petroleum oil; and wherein introducing the second stream tothe riser comprises introducing the second stream to the riser whereinthe second stream comprises a natural oil.
 15. The method of claim 13wherein introducing the second stream to the riser comprises introducingthe second stream to the riser at the second inlet, wherein the secondinlet is about 0.5 to about 12 meters above the first inlet.
 16. Themethod of claim 11 wherein contacting the feedstock with the crackingcatalyst comprises contacting the feedstock with the cracking catalystwherein the feedstock comprises a natural oil, wherein the natural oilis contacted with the cracking catalyst without any hydrotreating. 17.The method of claim 16 wherein contacting the feedstock with thecracking catalyst comprises contacting the feedstock with the crackingcatalyst wherein the natural oil comprises about 90 to about 100 weightpercent pyrolysis oil.
 18. The method of claim 16 wherein contacting thefeedstock with the cracking catalyst comprises contacting the feedstockwith the cracking catalyst wherein the natural oil comprises char. 19.The method of claim 11 wherein separating the riser effluent from thecracking catalyst comprises separating the riser effluent from thecracking catalyst wherein about 50 weight percent or more of thecracking catalyst fines exit the riser catalyst separator with the risereffluent.
 20. A fluid catalytic cracking unit comprising: a riser; aregenerator coupled to the riser; a first inlet coupled to the riser,wherein the first inlet is configured to introduce a first hydrocarbonstream; and a second inlet coupled to the riser, wherein the secondinlet is about 0.5 to about 12 meters above the first inlet, and thesecond inlet is configured to introduce a second stream comprising anatural oil.